Pacific Gas & Electric notified the authorities and employees Monday that it plans to file for bankruptcy protection. Not only will investors in PG&E Corp. be affected by the bankruptcy, but the California utility will also be allowed to break or renegotiate any or all of its contracts, putting YieldCos and other power producers at risk.
Entities that sell power to PG&E Corp. (PCG) will continue to sell that power to the utility. But if that power is currently being sold at above-market prices, those contracts may be renegotiated. The rapid decline in the price of solar power means that YieldCos with older power-purchase agreements (PPAs) signed with PCG are the most vulnerable. This is not to say that any or all PPAs will be broken or renegotiated, but the PG&E bankruptcy means that this is a real possibility that YieldCo investors should be prepared for.
Among YieldCos, Clearway (CWEN, CWEN-A) has by far the most exposure to PG&E’s bankruptcy. Other YieldCos with exposure are Atlantica Yield (AY), NextEra Energy Partners (NEP), and Pattern Energy Group (PEGI). TerraForm Power (TERP) and Brookfield Renewable Energy Partners (BEP) have minimal exposure to PG&E.
To get an estimate of how great each YieldCo's exposure is, we need to look at several factors:
1. How many PPAs are with PG&E?
2. Are these solar or wind PPAs? (Solar PPAs are likely to be at prices that are further above market.)
3. How old are the PPAs? (Older PPAs are likely to have higher prices because of the falling price for new installations, but older PPAs may also be nearer to expiry. A YieldCo with a soon-to-expire PPA will have a lot less to lose than one that still has 15 more years to run.)
Precedent shows there is a good chance that renewable energy contracts won’t be negatively impacted by a PG&E bankruptcy. But the risk isn’t zero.
In the following sections I estimate how each of the exposed YieldCos could be affected in what I consider to be a worst-case scenario. The impact on these firms will most likely be less (if PPAs end up being renegotiated at all). The impact could also be worse than my estimates if my guesses as to how these old PPA prices relate to current market prices are too conservative.
According to Clearway's most recent annual report, 23 percent of the YieldCo's electric power is sold to PG&E. By revenue, 12 percent of this is from conventional generation, which is less likely to be at inflated prices, and 11 percent is from renewables (see page 98). Because CWEN is highly leveraged, any reduction in these revenues will have an outsized effect on Clearway's cash available for distribution (CAFD).
Clearway's total 2017 revenue was $1,009 million, of which $121 million was from conventional power sold to PCG and $111 million from renewable power sold to PCG. In a worst-case scenario, investors might see conventional revenue reduced by 10 percent ($12 million) and renewable revenues reduced by 50 percent ($55 million). Again, these are estimates based on my understanding of the decline in PPA prices over time.
This would impact CAFD and potential dividends on a direct one-to-one basis, because there’s no reason for expenses to decline with this change.
Clearway’s 2017 annual CAFD was $267 million, guidance for 2018 CAFD was $285 million and guidance for 2019 CAFD was $295 million. I assume that 2019 guidance does not include any revenue reduction due to a PG&E bankruptcy.
Hence, in a worst-case scenario, we might see CWEN's 2019 CAFD reduced from an expected $295 million to $228 million (that’s a reduction of the $12 million plus $55 million referenced above), or 23 percent. The current annual dividend is $1.32 per share. If it were also cut by 23 percent, it would be reduced to $1.02 per share annually.
Assuming a yield of 7 percent for a YieldCo with no further downside exposure to PG&E, that puts the fair value of Clearway stock (CWEN and CWEN-A) at about $14.60.
There is a good chance that this worst-case scenario will not come to pass, however, and Clearway's PPAs will either be maintained or reduced less drastically. So $14.60 should be considered a point at which the YieldCo's stock is an attractive buy, despite the PG&E bankruptcy risk. Short-term market fluctuations have already driven the stock lower.
Pattern (PEGI) has one 101-megawatt wind farm selling power to PG&E. The farm began commercial operation in 2010, and the PPA ends in 2025. This accounts for 3.6 percent of PEGI's owned capacity.
Since this is a wind farm, the PPA is less likely to be as far above market price for a new wind farm than it might be for solar, so in a worst-case scenario, I would expect revenue from this farm might be reduced by 30 percent, lowering PEGI's revenues and CAFD by approximately $4.7 million, or 1 percent of annual revenue and 2 to 3 percent of expected 2019 CAFD. This is a small enough percentage of CAFD that I would expect PEGI to continue to maintain its dividend, although future dividend increases would likely be delayed.
At PEGI's current annual dividend of $1.69, and a dividend yield of 85 (because PEGI has few prospects for dividend growth in the next few years), I reach a worst-case valuation of $21.12. PEGI is trading at $19.38 as I write.
Atlantica Yield (AY) has a 280-megawatt wind farm that sells power to PG&E under a 25-year PPA that began in 2014. This is a much newer wind farm than Pattern's and so is even less likely to be priced above market. It accounts for 19.4 percent of AY's renewable generation, which produced $767 million in revenue in 2017.
A worst-case 15 percent PPA price cut (because the wind farm is so new) would likely reduce Atlantica's revenue and CAFD by $22.3 million, or about 12 percent of expected 2019 CAFD.
Atlantica might be able to absorb a 12 percent CAFD hit without reducing its dividend, but it would not be easy. So I will assume this would lead to a 12 percent dividend reduction to $1.27 per year.
At the 7 percent yield that I would expect a YieldCo without any further exposure to a PG&E bankruptcy to trade at, I reach a worst-case valuation of $18.10 for AY. As I write, the stock is trading at $18.83.
NextEra Energy Partners' (NEP) disclosure of assets is relatively opaque compared to other YieldCos, but investor presentations show the company has the 87-megawatt Golden Hills wind farm and 545 megawatts of solar in California.
The wind project has a different offtaker, so it’s unaffected by the impending PCG bankruptcy. However, PG&E is an offtaker for 300 megawatts of the 550-megawatt Desert Sunlight Farm, commissioned in 2015, in which NEP has a 275-megawatt stake. Let’s assume PG&E has 150 megawatts of NEP’s portion, dividing the 300-megawatt offtake in half. PG&E is also the offtaker on NEP’s 250-megawatt Genesis concentrating solar thermal plant built in 2007.
This means that PG&E is the offtaker for 400 megawatts of NEP's solar production, or about 8.5 percent of NEP's renewable capacity. The YieldCo also owns 542 miles of natural-gas pipelines.
NEP's annual revenue was $812 million, most of which comes from renewables, although I could not find an exact figure. I will assume that 80 percent of revenue comes from renewable energy and 20 percent from other divisions, and also that NEP's solar revenue from PG&E is reduced by 40 percent in a worst-case scenario. In that case, revenue and CAFD would be reduced by $34 million, amounting to a 7.5 percent reduction in annual CAFD.
NEP would likely absorb this CAFD reduction without reducing its dividend, but near-term dividend growth would likely be reduced. NextEra Energy Partners trades at a premium to other YieldCos based on a high 12-15 percent annual growth target. The current annual dividend is $1.80, and at a 5 percent dividend yield, the company would trade at $36. It is currently trading at $41.30 and a 4 percent yield.
Based on my assumptions, the worst-case for scenario these YieldCos (with the exception of Clearway) in the event of a PG&E bankruptcy is manageable. In almost all cases, the market prices are already reflecting these worst-case scenarios as if they were near-certainties.
NextEra Energy Partners remains overvalued, in my opinion, for reasons unrelated to the PG&E bankruptcy. Investors looking for bargains should look at other YieldCos.
Clearway, Pattern and Atlantica are currently trading near or below my worst-case valuations in the event of a severe reduction in revenue due to the PG&E bankruptcy. If you have cash available, this is a good time to initiate or add to your positions. If PPAs are reduced in accordance with my worst-case estimates, you still keep your investment. If the PPAs are upheld (which is a real possibility), you should see significant gains compared to the current stock price.
Tom Konrad, Ph.D., CFA, is an analyst, portfolio manager and freelance writer specializing in income-oriented green stocks. He is editor for AltEnergyStocks.com.
Disclosure: Long CWEN-A, AY, PEGI. Short NEP.
A report recently published in the journal Nature Sustainability outlines large racial and ethnic disparities in installations of rooftop solar.
Researchers with Tufts University and the University of California, Berkeley found that census tracts that are over 50 percent black or Hispanic have “significantly less” rooftop solar installations than census tracts with no majority or that are majority white — pointing to the equity implications of an unevenly developing solar industry.
“As renewable energy becomes more and more prominent, there’s a lot of hope that energy injustices that have been suffered in the past…will be overcome,” said Deborah Sunter, an assistant professor of mechanical engineering at Tufts and the lead author of the study. “When it comes to rooftop solar, there are a lot of economic benefits…and so unlike the fossil fuel industry, where energy injustice was attributed to exposure to negative consequences like pollution, with rooftop PV the injustice is more that certain communities are missing out on these economic benefits.”
Another of the study's authors, Daniel Kammen, a professor of energy at UC Berkeley and a former science envoy for the U.S. State Department, said the results should help "build a better and more inclusive energy transition,” with the recognition that "lack of access or a lack of outreach to all segments of society can dramatically weaken the social benefit" of solar.
The study relied on data from Google’s Project Sunroof, which shows the potential for rooftop PV on 60 million buildings throughout the United States and accounts for 58 percent of the national potential for energy generation from rooftop solar.
According to the results, in census tracts with the same median household income, communities with over 50 percent black residents have 69 percent less rooftop solar installed than tracts with no racial or ethnic majority. Majority Hispanic census tracts had 30 percent less installed. Majority Asian census tracts had on average 2 percent less solar installed than non-majority tracts.
Majority white communities, by contrast, had 21 percent more rooftop solar installed than tracts with no racial or ethnic majority.
Relationship Between Household Income and Rooftop PV Installation by Race and Ethnicity
The results are equally stark when accounting for home ownership. In census tracts with the same levels of home ownership, majority black census tracts had 61 percent less solar installed than tracts with no racial or ethnic majority, and majority Hispanic census tracts had 45 percent less. White majority census tracts had 37 percent more installed than no majority tracts.
The authors also noted that PV installations often result in a feedback loop: When a few residents in a community get solar, known as “seed” customers, it compels others to join. Communities without those first-mover customers show delayed solar adoption.
Majority black communities show disproportionately low “seeding,” according to the study. Among the census groups that the study looked at, 47 percent of majority black census tracts had no solar installations at all. That's well above the 24 percent of majority Hispanic census tracts without any solar installations — the census group with the next highest percentage of the population without solar PV.
But the authors note that when seeding does occur in communities of color, deployment “significantly increases” compared to other racial or ethnic groups.
Percentages of Each Census Tract With and Without Existing Rooftop Photovoltaic Installations
In addition to hypothesizing that seeding may play a role in lower levels of deployment in communities of color, researchers suggested that the whiteness of the solar industry’s workforce could be hurting deployment in those communities.
The Solar Foundation’s 2017 U.S. Solar Industry Diversity Study found that the solar industry was 74 percent white. White people also held between 78 percent and 90 percent of management and senior executive positions at solar companies. And only 27 percent of employer respondents to the foundation’s survey said they formally track employee diversity.
Melanie Santiago-Mosier, Vote Solar’s program director of access and equity, said the Nature report adds to the data showing the solar industry that it needs to improve.
“A significant step toward serving all communities across the country is making sure that our industry internally is very inclusive,” said Santiago-Mosier.
But she also said the industry, along with partners, is working to remedy its abysmal representation numbers. She pointed to initiatives like the Solar Equity Initiative launched last year by the NAACP, with partner support from groups like Vote Solar and the Solar Energy Industries Association (SEIA). That program aims to connect communities of color and low-income communities with solar infrastructure and provide solar job training.
Last year, the Historically Black Colleges and Universities Community Development Action Coalition and SEIA also signed an agreement to work together on recruiting more students into the industry from historically black colleges and universities. In 2016, SEIA also published a “best practices” guide to boost diversity and inclusion in hiring and recruitment.
Santiago-Mosier also said it’s essential for the industry to build partnerships on the ground with community organizations in underserved communities.
That’s especially important because communities of color have been and continue to be disproportionately impacted by pollution from fossil fuels. Grassroots organizations in these communities have long fought against the unequal environmental impacts they’ve faced. Because “this is an industry that was founded on the desire to do better,” Santiago-Mosier said solar must to do its part to mitigate those impacts.
“The promise of solar energy is one of lower and stabilized utility bills, investments in local economies and healthier communities,” said Santiago-Mosier. “The industry should…embrace the opportunity to use this information, use the data that’s out there to say: Where should we be going? Where should we be deploying solar and how should we be growing? […] The opportunity is there for the solar industry to really take a look at how it is serving its customers.”
Both Santiago-Mosier and Sunter said that aside from the study’s clear justice implications, the industry should also recognize the opportunity presented in communities of color where solar penetration is low. Increasing adoption in all areas of demand is the only way to grow markets to their full potential.
“Ultimately, if [the industry] wants to maximize adoption, they’re going to have to understand and address what these challenges and issues are that are resulting in minority communities basically being left out of this growth,” said Sunter. “If there isn’t intervention, it’s likely this disparity could continue to grow.”
Spain’s renewables industry is celebrating proposed legislation that could provide plant owners with guaranteed income for up to 12 years.
The regulatory framework would give renewable energy plant owners the option to stick with their current level of remuneration until the end of 2031, or switch to a formula based on the weighted average cost of capital that will be reviewed after six years.
Both options are seen as a vast improvement on the current system. Under a statutory review this year, the system would have seen a so-called "reasonable return" remuneration scheme falling about 42 percent in value, from a nominal 7.39 percent today to around 4.3 percent from 2020.
Spain’s former administration introduced the reasonable return concept in lieu of feed-in tariffs after it scrapped a generous FIT scheme in 2013. In theory, the concept allows for a fixed return on investment over the lifetime of a plant.
But it has been widely criticized by developers and investors. Detractors have noted that the investment levels for plants are based on theoretical rather than actual figures. Furthermore, the 7.39 percent is a pretax amount, which equates to a roughly 5 percent return after tax.
Plant owners have also struggled to achieve 7.39 percent in practice because of government accounting tricks.
But an even bigger bugbear is a clause allowing the government to review the level of reasonable return, in line with Spain’s national bond rate, every three years. This effectively meant investors had no long-term visibility of plant revenues.
This uncertainty spooked investors and has caused wind and solar installation rates to crater in Spain since 2013. More recently, intrepid solar developers have simply opted to ignore the regulatory risk attached to government bids and have built merchant plants instead.
However, the lack of investment in recent years means that Spain now faces an uphill struggle to meet its European renewable energy targets.
The Spanish renewable energy business association APPA estimates the country will need to invest €100 billion ($115 billion) to achieve its climate change goals.
The new law proposal shows Spain’s current left-wing government, which came to power last year, is keen to emphasize its commitment to renewables. Nonetheless, one feature of the draft legislation has puzzled observers.
The proposal gives plant owners the choice between a 7.39 percent remuneration rate for 12 years or an apparently vastly inferior scheme based on the weighted average cost of capital (WACC), which offers a return of around 7.09 percent and will be reviewed in six years.
Risk-happy investors might want to take a punt on the WACC being higher in 2026, but in practice the first option seems a no-brainer.
Hence it is unclear why Spain’s Ministry for Ecological Transition has even bothered with the WACC alternative, said Daniel Pérez Rodríguez, chief legal officer at Holaluz, a renewable energy retailer.
The secret appears to be in small print related to Spain’s liability from compensation claims stemming from the 2013 law. Spain faces a deluge of legal actions from renewable plant owners that lost out when FIT payments were stopped.
Under the proposed law, asset owners choosing to take the 7.39 percent option will have to accept a cap on any existing claims that effectively limits the state’s liability to within the amount it would pay under the new remuneration scheme anyway.
“If you have an ongoing legal process then there’s no advantage in pursuing it if you take this up,” said Jose María González Moya, managing director of APPA. “The government is saying: ‘Take your arbitration cases away, and I’ll give you 12 years at 7.39.’”
With most renewable asset owners expected to favor the higher-return, longer-term option, the question now is how soon the law might be passed.
This is not easy to predict given the balance of power between the ruling Spanish Socialist Workers' Party (Partido Socialista Obrero Español or PSOE) and the opposition People's Party (Partido Popular or PP).
The PSOE is governing with the slimmest representation of any ruling party in the history of Spain, and the PP, which crafted the 2013 regulatory framework, controls the senate.
Since the PSOE took control in June 2018, the PP has diligently stood in the way of practically all of the PSOE’s proposals. Given growing cross-party support for clean energy, though, it is expected to abstain from a vote on the renewables law.
Even so, experts believe it could be at least six months to a year before the legislation is passed. And things could take even longer if the PP and its allies find a way of forcing early elections. Renewable investors are praying that won’t happen.
Richard Heap, editor-in-chief at the analyst group A Word About Wind, which tracks wind sector investments, said: “It’s undoubtedly good for investors to have long-term visibility. [Trade body] WindEurope has spent years calling for governments to provide clarity to 2030.”
Renewable energy investors are cautiously optimistic that they'll finally get it.
Clean energy advocates are working to raise awareness about a “giant money fire hose” made available to the industry starting this year.
The glut of cash, tied to a portion of the federal Tax Cuts and Jobs Act of 2017, stems from an incentive framework called Opportunity Zones. The sleeper provision offers tax benefits to equity investors that put money into over 8,700 designated “economically distressed” opportunity areas. It’s designed to encourage investment in low-income communities that haven’t seen equal attention from investors.
The incentive holds several tax benefits, but it’s basically a capital gains shield. Equity investors can defer taxes on gains put into an “Opportunity Fund,” the investment vehicles organized to invest in the zones, until December 2026. If investors hold their investments for five to seven years, they can increase their basis on the investment by 10 and 15 percent, respectively. If investors hold their investments for at least a decade, they also don’t have to pay out taxes on capital gains made from investments in those zones.
The law is purposely flexible and scalable, with no cap on the money that can be deployed and few restrictions on the sectors that can take advantage, according to the Economic Innovation Group (EIG), a research and advocacy organization that helped design the legislation that modeled the Opportunity Zone provision in the tax bill.
In testimony to Congress, EIG President and CEO John Lettieri said, “This incentive has the potential to unlock an entirely new category of investors and create an important new asset class of investments.”
An EIG analysis estimated $6.1 trillion in unrealized capital gains was floating around in 2017. That’s such a huge lump of money that even if just a portion of it went to Opportunity Zones, EIG said it would already be the largest economic development initiative in the U.S. And, according to several experts watching the space, there’s big potential for the clean energy industry to take advantage.
“Industry folks should be jumping all over this,” said Jon Bonanno, chief experience officer at the nonprofit California Clean Energy Fund. “It’s a giant money fire hose, and we want to point it at the things we want.”
So far, much of the attention for Opportunity Zones has focused on the real estate industry. But because renewables projects are also long-term, place-based investments, advocates say clean energy is a natural fit. Wind and solar also don’t have the same gentrification and displacement implications tied to real estate development in low-income communities, one of the biggest concerns about the program.
The potential financial benefits are so great that Bonanno characterized it as a “watershed moment” for the clean energy industry.
“This is really an incredible mechanism,” said Bonanno. “It creates such compelling returns that we will see these assets going mainstream because of it.”
According to those working on Opportunity Zones, if a developer locates a project in one of the thousands of zones located throughout the U.S. and U.S. territories, it can be eligible for funds from a certified fund. That money would come into the project timeline at the same time equity usually does.
“For developers, it should actually be fairly straightforward and almost as simple as looking at a map,” said Cody Evans, a graduate student at Stanford University, who has been researching Opportunity Zones with professor Dr. Rebecca Lester. “From the developer’s perspective, it wouldn’t necessarily look any different than any source of funding; it would just likely come at a lower cost of capital.”
Evans added that developers also have to pass two tests to qualify property for the incentive. Projects have to add “substantial improvement,” increasing the basis of the property compared to the pre-investment value. Projects also have to derive 50 percent of gross income from active business in the zone.
For wind and solar developments, those qualifications should be pretty easy to meet. But so far, Evans said, “there’s a lot more runway for the industry to wake up to this tool and take advantage of it.”
Gregory Rosen, founder and principal at High Noon Advisors, said any opportunity that lowers the average weighted cost of capital for renewables deserves some attention. But he said recruiting investors will likely fall on the industry.
“Part of it is up to the industry to be proactive in educating folks,” said Rosen. “The jury is still out on how many [Qualified Opportunity Zone] investors there are that are interested in investing in solar.”
According to a list compiled by accounting and consulting firm Novogradac & Company, out of 49 funds that have registered to join the firm’s Opportunity Zone Listing, only three mention solar as an investment focus. After a call for letters of inquiry from fund managers working on Opportunity Zone projects, the Rockefeller Foundation — working with the Kresge Foundation — said only one of the 141 responses it received had a clean energy focus, and even that had a real estate bent, describing its aim as “energy efficient property development.”
Bonanno called the lack of attention for renewables “abysmal.”
“The renewable energy business needs to get their act together and focus on this,” he said.
Despite the delay, those watching the funding expect 2019 to be a “boom year,” said Abraham Reshtick, a business and tax attorney at Mintz. That’s in part because investing this year allows investors to realize the most benefits with the timeline of the incentive. The incentive can also be paired with the soon-declining federal Investment Tax Credit and Production Tax Credit benefits.
At the same time, Reshtick added, “There needs to be the right opportunities.”
“It’s the next few months that will give us the best indication as to whether this is an attractive enough program,” he said.
Even as advocates urge the renewables industry to leverage the funding, though, they also caution that regulations for Opportunity Zones are yet to be finalized.
The IRS released an initial batch of proposed guidance in October, offering some clarity on the particulars of the law. But the agency canceled a January 10 public hearing on those regulations due to the ongoing government shutdown. It’s anyone’s guess when that meeting will actually happen. Investors are also awaiting additional guidance.
In the meantime, it’s difficult for funds to fully organize. Though those working on the funding, like Rockefeller and Kresge, have seen a surge of activity — Rockefeller said the responses they received are a “testament to the enormous market interest” — adoption will be halting until there’s more clarity.
Before the rules are finalized, stakeholders are also hoping for some changes. Currently, Evans said, the rules make it difficult for multi-asset funds to participate in the program. He said allowing that participation would encourage more investment and allow diversification of risk across a portfolio.
And an “insane oversight,” according to Bonanno, is the lack of a community impact requirement tied to the funding. Though the program is structured to increase investments in low-income census tracts, the law doesn’t say the project necessarily has to benefit the community in any measurable way.
“You could just be a banker and you could invest in a solar project — you stick the solar project in an Opportunity Zone. They don’t see a penny, they don’t get any of the work, and honestly, it’s not necessarily helping those communities,” said Rosen at High Noon Advisors. “It’s our collective responsibility to take these opportunities and proactively have them benefit communities.”
This is especially a concern in Opportunity Zones already experiencing displacement of low-income residents and communities of color. Though EIG notes that under 4 percent of the selected census tracts have seen high socioeconomic change between 2000 and 2016, some communities are skeptical.
A study that looks at the potential for gentrification stemming from the Opportunity Zone program, conducted by a national coalition of real estate developers and investors called LOCUS, in partnership with George Washington University, highlighted downtown Oakland, downtown Portland, downtown Newark, and Seattle’s downtown and International District as the most vulnerable for “accelerated gentrification” without policies in place to stop it.
But staunching the negative impacts of the law may be left to states and cities. California, for instance, still has a state-level capital gains tax in place and could require certain community impact requirements in order to grant an exemption.
How implementation shakes out will be especially important in states and metropolitan areas where gentrification is already an issue. In the LOCUS ranking of vulnerable areas, 13 of the top 50 vulnerable locations are in California and 13 are in New York. Many of the most vulnerable Opportunity Zone locations are also in states with significant renewables development, including California, New York, New Jersey and Massachusetts.
AES Corporation launched the world’s largest battery plant paired with solar generation Tuesday, on the Hawaiian island of Kauai.
This type of power plant produces cheap, clean energy and uses batteries to deliver power when it is most valuable, instead of just when the sun shines. That’s vital to decarbonizing the island grids of Hawaii, which struggle with too much solar power at midday but still rely on fossil-fueled peaker plants in the evening.
In the two years since AES announced the project, a flurry of headlines ensued as energy companies drove the price point for dispatchable solar successively lower. While the most attention-grabbing bids bank on several years of further battery cost declines, the Kauai plant is up and running right now.
The Kauai Island Utility Cooperative (KIUC) is finishing up commissioning for the Lawai Solar and Energy Storage Project, which combines 28 megawatts of solar photovoltaic capacity with a lithium-ion battery capable of storing 100 megawatt-hours.
The battery alone holds more energy than all but one other U.S. plant: the 120 megawatt-hour facility AES built in Escondido in 2017. Taken as a whole, Lawai’s storage capacity outranks any other operational solar-paired battery system in the world, according to Wood Mackenzie Power & Renewables. But the ever-growing solar-plus-storage project pipeline means that title won’t be safe for long.
“This market is growing at a phenomenal rate,” said AES President and CEO Andrés Gluski. “I think you’re going to see a...lot [fewer] peaker plants.”
AES owns and operates the plant on behalf of KIUC, under a power-purchase agreement pegged at 11 cents per kilowatt-hour.
The plant delivers solar power when a standalone solar plant can’t: at night. That offsets the peaker plants that turn on for the evening peak; in Hawaii, those plants tend to run on imported oil, at considerable expense.
“We’re in the money anytime you can dispatch to offset oil generation,” said Woody Rubin, president of AES Distributed Energy.
Lawai can crank a full output of 20 megawatts for five hours. With 100 megawatt-hours of stored energy, the battery can also operate more like a baseload plant, delivering a lower amount of power for more hours through the night until the sun comes back up. AES expects to offset 3.7 million gallons of diesel each year by dispatching more cost-effectively than the fossil-fueled incumbents.
An additional capability, for special occasions: The plant can black-start the overall grid if an outage knocks it out.
The battery technology allows many more use configurations than a standalone solar plant, which just produces electricity. As such, the process of testing out all the different functions has been “a fun time,” Rubin said.
“You open up the new toy and you start playing with it,” he said.
With the new plant, Kauai will be able to operate for certain parts of the day entirely from renewables, Rubin said.
Meeting Hawaii’s legislative mandate of 100 percent renewables by 2045, though, requires more than midday solar abundance. The early solar-plus-storage plants (Tesla/SolarCity also built one on Kauai) proved that cheap solar power could serve the grid when needed rather than flooding it when there’s already enough power.
“There’s too much discussion about renewable energy; there’s not enough discussion about capacity,” Gluski said of decarbonization in general. “With batteries in place, it’s a game-changer — you can produce very cheap energy and turn it into that 24/7 capacity.”
Now, KIUC will be able to serve up to 40 percent of evening peak power with stored solar energy, President and CEO David Bissell said in a statement.
Kauai's pioneering projects have already inspired a wave of followers. AES is building another hybrid system at Pacific Missile Range Facility/Barking Sands Naval Base; it will combine 19.3 megawatts of solar capacity with 70 megawatt-hours of energy storage.
Just last week, the Hawaiian Electric Company asked regulators to approve seven new solar-storage plants across the islands of Hawaii, Maui and Oahu. That move confirmed that this type of resource will play an increasingly central role in Hawaii's energy future. All but one of the proposed projects beat Lawai’s price per kilowatt-hour.
AES had two massive plants in that portfolio: one with 30 megawatts/120 megawatt-hours and one with 60 megawatts/240 megawatt-hours, both clocking in at 8 cents per kilowatt-hour.
The concept has also made its way to the mainland, with median bids of 3.6 cents per kilowatt-hour in Xcel’s Colorado solicitation, and a 4.5 cent per kilowatt-hour hybrid system going to Tucson Electric Power. (The lower costs reflect several factors, include construction costs on the mainland versus Hawaii and the relative size of the battery component compared to the solar capacity.)
It’s important to note that KIUC made the economics work as a relatively tiny company. It serves 65,000 customers with a peak capacity of 125 megawatts. The new plant brings its generation mix to 50 percent renewables, well beyond most any other utility at this time.
“Look to KIUC as a vanguard in the energy transition,” said Daniel Finn-Foley, energy storage analyst at Wood Mackenzie Power & Renewables. “It made sense politically and economically there first, but that same stiff wind of change that swept Hawaii is approaching the mainland too.”